Trapped Oil Research Articles

Chemical enhanced oil recovery using carbonized ZIF-67 MOFs and sulfonated copolymers at high reservoir temperatures

Traditional nanoparticle and polymer-based enhanced oil recovery methods face challenges such as nanoparticle agglomeration and polymer adsorption, particularly at elevated reservoir temperatures. This study introduces hybrid polymeric nanofluids, combining carbonized Zeolitic Imidazolate Framework-67 (ZIF-67) with sulfonated copolymers to address these issues. Viscosity tests were conducted at 25 °C, 50 °C, 75 °C, and 90 °C, revealing a 39.67 % increase in viscosity at 90 °C, attributed to electrostatic and hydrogen bond interactions. For subsequent analyses—stability, adsorption, and core flooding—75 °C was selected as the representative high reservoir temperature. Stability assessments, confirmed via UV–Vis spectroscopy, demonstrated nanofluid durability over at least seven days. Carbonized ZIF-67 reduced polymer adsorption on rock surfaces, enhancing oil recovery and reducing environmental impact. Dynamic core flooding experiments showed a 45.8 % improvement in oil recovery by the hybrid nanofluid on carbonate rock samples. The hybrid nanofluid increased RF and RRF, improving the mobility ratio and redirecting flow to lower-permeability zones, reducing unswept oil and enhancing macroscopic sweep efficiency. Winsor Type III emulsification during the post-flooding phase of polymer-nanoparticle injection significantly improved trapped oil mobilization. Reduced contact angles from 170° to 100° altered the wettability, enhancing oil recovery. Carbonized ZIF-67 nanoparticles increased viscous forces, reduced capillary forces, and minimized polymer adsorption. The polymeric nanofluid achieved a capillary number of 1.0 × 10−3, two orders higher than that of polymer alone, resulting in superior performance. Injectivity optimization showed shear rates of 15.9 s−1 in 1700 mD cores and 79.8 s−1 in 80 mD cores, causing pressure drops of 15 psi and 1200 psi, respectively. This highlights injectivity challenges in 80 mD cores, while cores ≥ 290 mD are ideal for our polymer-nanoparticle hybrid applications.

Sustainable potassium-doped graphene oxide from oak fruit agricultural waste for a synergistically improved nanofluid-surfactant slug for enhancing oil recovery

This study presents an eco-friendly solvothermal method for synthesizing potassium-doped graphene oxide (K-GO) from agricultural waste, specifically oak fruit. Various spectrographic analyses, including XRD, FTIR, Raman, and UV–Vis, confirmed the successful synthesis of graphene oxide. The synthesized K-GO was combined with different surfactants to create nanofluids to enhance oil recovery. Anionic sodium dodecyl sulfate (SDS) demonstrated the best performance among the surfactants tested. When 250 ppm of K-GO was added to a 2500 ppm SDS solution, the surface tension was reduced by over 10 %. The study of zeta potential experiments validated that the K-GO-SDS nanofluid is compatible with sandstone reservoirs. Furthermore, the interfacial tension between the K-GO-SDS nanofluid and crude oil decreased by approximately 40 %. Batch adsorption studies showed that the combination of SDS and K-GO significantly reduced surfactant loss to reservoir surfaces by up to 32 %. Additionally, incorporating K-GO resulted in a notable improvement in wettability alteration, with contact angle measurements showing an improvement of over 20°. The sustainable synthesis of potassium-doped graphene oxide (K-GO) facilitates synergistic interactions with sodium dodecyl sulfate (SDS), thereby optimizing the formulation of nanofluids for enhanced oil recovery applications. This combination demonstrates superior efficacy in accessing trapped oil compared to using surfactants alone, highlighting the significant potential of K-GO-SDS nanofluids in advancing oil recovery techniques.

Experimental study of ultra-low IFT foam flooding for low permeability reservoirs

Foam flooding is an effective oil displacement technique to improve fluid sweep efficiency and increase oil recovery. The objective of this paper is to investigate the applicability of ultra-low IFT foam flooding for low permeability oil recovery under the conditions of WX reservoir block in Tuha oilfield (84°C, 86,072 mg/L). A modified amphoteric hydroxy sulfobetaine surfactant (Cn-HSB) was formulated as a foaming agent based on the principle of compatibility with crude oil that could achieve the ultra-low interfacial tension (IFT) and strong foamability simultaneously. This is shown to reduce the oil/water dynamic IFT (DIFT) to an ultra-low value of the order of 10−5 mN/m (0.10wt%), as well as produce a foam volume and half-life of 448 mL and 2567 s, respectively. In addition, results of IFT and foam quality tests indicate that the modified Cn-HSB has good thermal stability and excellent salinity-resistance. Moreover, the ultra-low IFT foam flooding has an ideal injectivity and oil displacement efficiency in low permeability porous media that can mobilize the trapped oil in k = 1.50 × 10−3μm2 with a threshold pressure gradient of 0.115 MPa/m. This improves oil displacement efficiency about 15%OOIP. Fundamental knowledge gained from this research gives insight into the application of ultra-low IFT foam flooding in low-permeability reservoirs under a combination of specific reservoir conditions.

An Overview of Oil Recovery Techniques: From Primary to Enhanced Oil Recovery Methods

As we all know, numerous methods have been invented for better managing of the reservoirs to recover the trapped oil from them as much as possible. These techniques included primary techniques that were implemented primarily at the beginning of this industry. As these techniques were not effective enough, secondary techniques, like; water flooding and gas injection methods were created and the amount of recovered oil were increased, as well. On the contrary, the demand for more oil was raised up and it was felt that much more effective techniques are necessary. It resulted to creation of Enhanced Oil Recovery Techniques and these techniques are included; thermal methods (steam injection, steam assisted gravity drainage and in-situ combustion), Chemical methods (alkali flooding, surfactant flooding, polymer flooding, foam flooding, and combination of alkali-surfactant-polymer flooding), and microbial EOR. The most promising technique is microbial EOR because of being cost-effective and ecofriendly. GEMEOR (Genetically Engineered MEOR) and EEOR (Enzyme Enhanced Oil Recovery) are two new trends of MEOR that own potential hopes in petroleum industry.

Bio‐enhanced oil recovery (BEOR) methods: All‐important review of the occasions and challenges

AbstractBio‐enhanced oil recovery (BEOR) is an advanced and innovative approach in the oil industry that could be a potential solution to increase oil production from existing reservoirs using technologies based on biological methods. Nevertheless, there has been a lack of comprehensive reviews that elucidate the various aspects and potential of different BEOR methods and processes. This review summarizes the recent progress of various methods employed in BEOR, exploring their applications and highlighting their distinct advantages. BEOR employs different techniques, including microorganisms and biomicrobes microbial enhanced oil recovery (MEOR), enzymes, biopolymers, bionanomaterials, alkaline, and biosurfactants to increase oil recovery. Microorganisms contribute significantly to BEOR through metabolic processes that result in the production of gases and acids. The role of enzymes is to enhance the fluid flow and thereby facilitate oil production. Biosurfactants reduce the interfacial tension (IFT) between oil and water and mobilize the trapped oil. Biopolymers are obtained from biological sources such as plants, microorganisms, and algae. Biopolymers can interact with oil, which is well‐used in the process of EOR. Bionano processes represent a fusion of biology and nanotechnology, integrate the advantages of both microorganisms and nanoparticles, and provide a synergic effect for EOR. The BEOR revealed an attractive potential to be an effective approach to maximizing the oil recovery considering environmental, economic productivity, and sustainability issues. Also, this review encourages further studies and development in this field for fully exploiting BEOR's capacity and meeting the ever‐increasing needs of energy resources with a sustainable viewpoint.

The use of biological catalyst (enzyme) for enhanced oil recovery in Niger Delta

This study is aimed at using bio-catalyst (enzymes) for enhanced oil recovery in Niger Delta. Three different enzymes produced from microbial isolates with code ID; LPE1, LPE2 and AME were use in analyzing enzymes effect on the rock-fluid and fluid-fluid interaction test to simulate the conditions in the reservoir. The tests carried out include; wettability, interfacial tension (IFT) and adhesion test. The results from these tests show that addition of enzymes to rock-fluid interface has the potential of enhancing recovery of crude oil. From the result, the use of enzyme caused an alteration in the wettability of the rock from oil-wet to water-wet with a 33° difference. The selected enzyme LPE1 showed a significant difference in reduction of interfacial tension by a factor of 4, while LPE2 and AME did not show any significant difference. In conclusion, the wettability and IFT tests results were the basis for choosing LPE1 for core flooding process. Enzyme (LPE1) flooding after waterflood was able to give an additional 11.5 % oil recovery. From the results, the percentage recovery is a pointer to the fact that when the primary and secondary oil recovery methods are no longer viable in terms of economics, the Enyme enhanced oil recovery is the best method of mobilizing trapped crude oil in the Secondly, there is no negative effect on the crude oil quality using the enzyme-EOR because the enzymes only increase the rate of the chemical reaction on the rock media without undergoing any permanent chemical change.

A critical review of carbonate reservoir wettability modification during low salinity waterflooding

The nature of carbonate reservoirs promotes the adsorption of oil onto the rock surface hence making oil recovery a challenge even with the interventions of varied chemical EOR methods. Recently, low salinity water flooding has become of great interest since it is cost-effective and environmentally friendly. Although low salinity waterflooding has been highly investigated in sandstone reservoirs, it is not the same for carbonate reservoirs due to its complexities. Nonetheless, it has been proposed as a favourable technique to mobilise the trapped oil in carbonate reservoirs. Wettability alteration is regarded as the most accepted mechanism for low salinity flooding but has not been well understood making field scale applications doubtful. In this paper, we present a detailed review of the wettability alteration mechanisms in carbonate reservoirs during low salinity waterflooding. Parameters influencing wettability alteration in carbonates and the interactions that occur at the rock/brine/oil interface are also presented. The different methods utilised for wettability measurements during low salinity waterflooding are also reviewed including their drawbacks and advantages and recommendations. This will provide an improved understanding of the low salinity flooding application in carbonate reservoirs.

A new hybrid rate optimization method to enhance oil recovery from Brugge field using streamline-driven injection efficiencies

BackgroundOptimization of waterflooding projects traditionally focuses on optimizing rate control of injector/producer wells to enhance recovered oil from reservoirs. In such projects, a complex, constrained, multi-variable problem is optimized to enhance the oil recovery performance of reservoirs. MethodsStreamline-based rate optimization has been applied as a robust method to find the optimal water injection strategy. The present study aims to optimize injector/producer wells rates using streamline-driven injection efficiencies. A heuristic algorithm (the so-called weights algorithm) was used in previous works. This study proposes a new hybrid particle swarm optimization (PSO)-weights method. The weights algorithm oil recovery results are dependent on the initial guesses to start searching the domain. PSO global search ability provides a proper set of initial guesses for the weights algorithm. Significant findingsThe hybrid method is implemented to optimize two reservoir models. First, the PSO-weights algorithm is applied on a 2-D homogenous model with 13 wells; after optimization, injectors/producers’ computed rate converged to known optimal rates. Second, the proposed algorithm has been tested to optimize the Brugge field and successfully afforded it quickly. The field oil production rate (FOPR) and the total field oil production (FOPT) results indicate an improvement in oil production. In addition, less trapped oil in saturation contours in different reservoir layers is reported.

Investigation on the interactions of resinous and asphaltenic synthetic oils and silicon oxide nanoparticles stabilized by different ionic liquid-based surfactants: interfacial tension and wettability alteration studies

The effects of the main components of crude oil, especially resin and asphaltene fractions, are essential concerns for efficient enhanced oil recovery (EOR) processes, especially during chemical injection processes. This importance comes from the nature of these two fractions which can act as surface active agents with undeniable effects on the used chemical for interfacial tension (IFT) reduction and wettability alteration. In this way, the effect of silicon oxide nanoparticles (SiO2-NPs) concomitant with two ionic liquids (ILs), namely 1-dodecyl-3-methyl imidazolium chloride ([C12mim][Cl]) and 1-octadecyl-3-methyl imidazolium chloride ([C18mim][Cl]), is investigated on the wettability alteration and IFT reduction using synthetic oils prepared by dissolving the extracted resin and asphaltene fractions with a concentration of 1–5 wt%. The measurements reveal that the effect of resin fraction is less than the asphaltene fraction for IFT reduction and wettability alteration. The sole presence of resin fraction reduces the IFT from 35.3 to 28.3 mN/m as the concentration is increased from 1 to 5 wt%, while a similar increase in the asphaltene fraction concentration reduces the IFT from 35.5 to 19.1 mN/m. Besides, the results reveal that the presence of [C12mim][Cl] in the range of 0–1000 ppm leads to a reduction in IFT from its maximum value of 35.3 to 0.81 mN/m, while in the case of [C18mim][Cl] with similar concentration variation, IFT is reduced from 35.3 to 0.7 which means the better effect of IL with longer chain length on the IFT reduction. Further analysis revealed that the effect of asphaltene fraction on the IFT is higher than resin fraction since the minimum IFT value was observed for [C18mim][Cl] with the value of 0.58 mN/m, while the contact angle (CA) values revealed revers effect for asphaltene fraction compared with the resin fraction. In general, regardless of the used IL, it seems that ILs leading to better wettability conditions which are crucial for EOR purposes and even better IFT values that can mobilize the trapped oil toward production points. Besides, further measurements revealed a positive effect of SiO2-NPs concomitant with the ILs to move the wettability toward the strongly water-wet condition with CA values of 29.2° and 28.3° for SiO2-NPs concentration of 1000 ppm and 1000 ppm of concentration for [C12mim][Cl] and [C18mim][Cl], respectively, for resinous synthetic oil (RSO) (5 wt%) while no meaningful effect regarding the SiO2-NPs presence at the different concentrations (100–2000 ppm) is found on the IFT reduction. A similar trend is observed for asphaltenic synthetic oil (5 wt%)/aqueous solution (SiO2-NPs with a concentration of 1000 ppm + ILs with a concentration of 1000 ppm) which reduces the CA to 26.3° and 37.8° for [C12mim][Cl] and [C18mim][Cl]), respectively.

Impact of surface-modified silica nanoparticle and surfactant on the stability and rheology of oil-in-water Pickering and surfactant-stabilized emulsions under high-pressure and high-temperature

Emulsions have a wide range of applications, and with the advancement in the use of nanoparticles to form stable Pickering emulsions, it is important to understand their rheological properties to infer their stability under high-pressure and high-temperature (HPHT) compared to the emulsion formed using conventional surfactants. In oil and gas production strategies, oil often forms an emulsion with brine either within reservoirs or at surface facilities in the presence of natural or artificial surfactants. Nanoparticles are also being explored to increase oil recovery from matured reservoirs. In various instances, stable emulsions are either formed in-situ (within the reservoir) or at surface facilities or injected into the reservoir to mobilize the trapped oil. It is also essential to understand their rheology for efficient oilfield application. This study investigates the impact of surface-modified silica nanoparticles (Ludox CL), NaCl salt, and surfactant on the stability of oil-in-water Pickering and surfactant-stabilized emulsions under high-pressure (0.1–10) MPa and high-temperature (303–363) K conditions. The viscosity of emulsion samples was measured at varying shear rates (0.1–1000) s−1. The viscoelastic behavior (G′, G″, η*, and δ) of the Pickering emulsion and surfactant-stabilized emulsion were also measured. The stability of the emulsions was measured in terms of changes in emulsion viscosity and droplet diameter. Both emulsions showed non-Newtonian shear thinning behavior and an increase in droplet diameter under HPHT conditions. However, the surfactant-stabilized emulsion exhibits a greater degree of change in emulsion viscosity and droplet diameter than the Pickering emulsion. It indicates that the Pickering emulsion showed better stability than the surfactant-stabilized emulsion under HPHT conditions. Hence, Pickering emulsions are an incredibly promising tool that might be employed in HPHT applications, especially for enhanced oil recovery applications, due to their better rheological stability.

Wettability alternation and interface tension modification for enhanced oil recovery in oil-wet carbonates: A comparative study of different surfactants

With the ever-growing demand for oil and gas today, and the increasing difficulty of recovering hydrocarbons from carbonate reservoirs, it is vital to apply enhanced oil recovery (EOR) techniques. Carbonate reservoirs typically have natural fractures and are found to have oil-wet matrixes natively, making EOR in these reservoirs more challenging. Wettability alteration is a viable mechanism in this scenario. However, there is an ambiguity about which chemical solutions perform better in carbonate reservoirs. This study assessed the capabilities of various surfactants and their ability to alter wettability and interfacial tension under surface and reservoir conditions. Fifty-six surfactants from four different chemical groups (cationic, anionic, zwitterionic/amphoteric, and nonionic) were screened for their stability and emulsification. Then, spontaneous imbibition experiments were performed on an Indiana limestone outcrop to assess the impact of wettability and interfacial tension on oil recovery for both aged and non-aged cores. Results show that six out of the eleven successful surfactants were nonionic. Furthermore, we found that, for oil-wet rocks, wettability alteration increases production in the early stages of imbibition, while the reduction in interfacial tension increases the recovery in the later stages by unlocking trapped oil in the pore matrix. Exploratory data analysis showed that IFT is the most correlated parameter with the recovery from the aged cores, while contact angle was highly correlated with both aged and non-aged cores. Finally, a generalized automated spontaneous imbibition model was derived based on the dimensionless exponential and hyperbolic functions. The fitting results show that both the exponential and hyperbolic models complied with the trend of spontaneous imbibition. However, the exponential model better matches the surfactant imbibition data. The results from this work help unlock the potential of carbonate reservoirs and maximize the oil recovery to solve the current global energy challenge.

Study on Multi-flow Field Characteristics of Unloading Groove Spacing of Bidirectional Gear Pump

Improving the output flow quality of the high-precision micro bidirectional gear pump can effectively improve the position control accuracy and dynamic characteristics of the electro-hydraulic actuator. In order to meet the appeal requirements and reduce the vibration and noise of the gear pump and prolong its working life, this paper starts with the research of the key part of the gear pump–the unloading groove structure. The three characteristics of trapped oil phenomenon, cavitation phenomenon, and flow were used as key indices to evaluate gear pump performance. Using numerical simulation analysis, the dynamic grid simulation method was used to explore the influence of unloading groove spacing on the transient multi-flow field characteristics of the gear pump under conventional design range. Our results show that reducing the distance between unloading grooves can greatly reduce the trapped oil pressure and the amount of gas precipitation in the flow field, while reducing flow pulsation and improving volumetric efficiency. However, when the unloading groove spacing is too small, the instantaneous flow curve loses the pulsation characteristics and the flow stability decreases. Considering the influence of the gear pump on the accuracy of the electro-hydraulic actuator and the performance of the gear pump itself, the analytic hierarchy process was used to obtain the 1 mm unloading slot spacing, which best meets the engineering requirements of high flow accuracy and low vibration noise. The results provide a basis for work on the structural optimization of high-precision micro gear pumps.

Kontrola niestabilności kapilarnej w warunkach hydrodynamicznego oddziaływania na złoże

The paper presents the results of studies on optimisation of water impact on a reservoir by means of sequential periodic increase in hydrodynamic pressure in order to extract capillary trapped oil. The method provides a coordinated account of both displacement conditions and capacitive-filtration characteristics of fluid-saturated reservoirs. The results of experimental, theoretical and field studies of mass transfer processes in the presence of hydrodynamic nonequilibrium in heterogeneous porous media are presented. This paper considers a case where capillary forces are the determining factor for the displacement of immiscible liquids. Laboratory test results have shown that the formation of CO2 in the reaction of an alkaline solution with naphthenic components can make an additional contribution to the control of surface tension in porous media. A series of experimental studies were carried out on a core sample model to simulate the oil displacement by in-situ generated CO2 gas-liquid system. The article offers an analytical and technological solution to the problem of ensuring the value of “capillary number” and capillary penetration corresponding to the most complete extraction of trapped oil by regulating the “rate” of filtration (hydrodynamic injection pressure). The paper presents the field cases of implementing the new reservoir stimulation techniques to increase sweep efficiency. For effective residual oil recovery in fluid flow direction, conditions of stepwise (staged) maintenance of specified hydrodynamic water pressure at the boundary of injection contour are considered. Estimated calculations allow to determine time duration and stage-by-stage control of injection pressure as a requirement for reaching the expected increase in oil recovery.

Experimental Investigation of Asphaltene Deposition and Its Impact on Oil Recovery in Eagle Ford Shale during Miscible and Immiscible CO2 Huff-n-Puff Gas Injection

One of the challenges in extracting oil from unconventional resources using hydraulic fracturing and horizontal drilling techniques is the low primary recovery rate, which is caused by the ultra-small permeability of these resources. Consequently, it is essential to investigate gas injection methods to produce the trapped oil in shale formations. However, the injection process can cause asphaltene depositions inside the reservoir, leading to plugging of pores and oil recovery (OR) reduction. There has been limited research on using gas injection techniques to improve oil production in tight/unconventional resources, although carbon dioxide (CO2) and gas-enhanced oil recovery methods have been used in conventional resources. In order to determine whether or not the cyclic (huff-n-puff) CO2 process improves OR and aggravates asphaltene precipitation, a rigorous experimental investigation was undertaken utilizing filter membranes and Eagle Ford shale cores. After the minimum miscibility pressure was calculated for CO2, various injection pressures were selected to perform CO2 huff-n-puff experiments. Investigations were carried out at 70 °C on injection pressure, cycle number, production time, and huff-and-puff mode injection. The results demonstrated that when the pore size structure of the membranes used was smaller and gas injection cycles increased, a higher asphaltene weight percent (wt %) was determined during the static experiments (i.e., employing filter paper membranes). Miscibility improved OR in dynamic testing (i.e., using shale cores), but a more oil-wet system was detected in wettability measurements taken following CO2 huff-and-puff tests. The plugging impact of asphaltene particles on the pore structure was studied using optical microscopy and scanning electron microscopy imaging. Following the huff-and-puff tests, a mercury porosimeter revealed how severely the pores were plugged, and after the CO2 tests, the pore size distribution reduced as a consequence of asphaltene deposition. This study examines the significance of CO2 injection in OR under miscible/immiscible conditions to identify the critical parameters that could impact the effectiveness of CO2 huff-n-puff operation in unconventional formations.

Risk matrix for legacy wells within the Area of Review (AoR) of Carbon Capture & Storage (CCS) projects

The success of CCS depends on the capacity, injectivity, and confinement by the storage medium. Thousands of wells drilled over the past century with the intention to find the trapped oil and gas may penetrate the containment seals. These wells may provide leakage pathways for the CO2 to escape and contaminate the underground sources of drinking water (USDW) or reach the surface in the worst-case scenario. Identifying the risky wells penetrating the containment seals and predicting their current as well as future well integrity is the most challenging task when limited data is available. This paper proposes a unique methodology for risk assessment of the wells penetrating the containment seals based on the proximity of these wells from the proposed injection location, mechanical integrity, and accessibility of these wells over the lifecycle of the CCS project. This helps in identifying the wells which need immediate attention from the wells that need little to no attention. It also highlights the corrective actions necessary for the success of the CCS project as well as help estimate the approximate cost required to perform the corrective actions. This methodology focuses on all wells (producers, injectors, orphan, abandoned, water, stratigraphic, etc) while the majority of the studies found in literature focused on wells with sustained casing pressure (SCP) reports and cement bond logs (CBL). The proposed risk matrix, if applied to future CCS projects across the globe, will uniformly categorize the wells within the Area of Review (AoR).

Hybrid Carbonated Engineered Water as EOR Solution for Oil-Wet Carbonate Formation

Carbonated water has proven advantages over conventional CO2 injection in terms of arresting free CO2 mobility, low-pressure injection, lower volume requirement, and higher efficiency. The term “engineered water” is designated to selective ion-spiked injection water with the advantage of the ion-exchange reactions with the rock minerals and releasing trapped oil. This article investigated the synergic effect of dissolved CO2 and engineered water for oil recovery and understanding inner mechanisms. Recovery efficiencies were evaluated through coreflood studies, which revealed that the hybrid water could recover 6–10% more oil than engineered water and about 3% more than carbonated water. HP-HT pendant-drop studies show the insignificance of IFT reduction. Wettability change from oil wet to near-water wet is attributed as a significant factor. The dissolution of Ca2+ and Mg2+ and deposition of SO42− observed in coreflooding may have a significant contribution to oil recovery. Pore enlargement evidenced in NMR-PSD and NMR-ICP results support this claim. The study confirmed that the EWI-CWI hybrid technique could be a promising EOR method, eliminating the requirement for high-pressure injection, the problems of gravity segregation, and the early breakthrough of CO2. It can also be an effective EOR solution, providing a significant cost advantage and higher oil recovery in addition to the environmental benefits of CO2 sequestration.

Synthesis and application of the novel metal nitrate/graphene oxide nanocomposites in enhancing oil recovery at ultra-high salinities

Herein, it was aimed to enhance the oil recovery by exploiting the mechanisms involved in leveraging the rock and fluid characteristics. To this end, various nanostructures, including nanocomposites of Poly Citric Acid (PCA) grafted graphene oxide (G.O) and Al, Cu, and Mg nitrates, were synthesized. The prepared nanocomposites were investigated at high salinities (8 wt% CaCl2 and 8 wt% NaCl) for enhanced oil recovery (EOR). Rock wettability and interfacial tension (IFT) enhancement were investigated to show improvement in the oil recovery. Furthermore, core flood experiments were performed using a crude oil sample and a water solution at high salinities (8 wt% CaCl2 and 8 wt% NaCl). The results revealed that synthesized nanofluids were stable at high water salinities and could displace the trapped oil in sandstone core samples, implying nanofluids' positive role in oil recovery improvement. Also, contact angle values were measured at different concentrations by the time. The results indicated the wettability alteration as an effectual mechanism in the EOR through applied disjoining pressure by these particles. As the second mechanism for fluid-fluid interactions, interfacial tension reduction was investigated at three concentrations. It was also found that at 500 ppm concentration, the best tertiary recovery enhancement of 13.55% was obtained for Mg/GO-g-PCA followed by Cu/GO-g-PCA (11.3%) and Al/GO-g-PCA (9.72%), which is a remarkable result. So, these novel synthesized materials can be applied at such high salinities (8 wt% CaCl2 and 8 wt% NaCl). As high water salinity is one of the main challenges in using chemicals for enhancing oil recovery, the results of this study can be beneficial to overcome this issue.

Coreflood-on-a-Chip Investigation of Oil Bank Formation in Low Interfacial Tension Chemical Floods at Favorable and Unfavorable Viscosity Ratios

Summary An efficient tertiary chemical flood involves the chemicals displacing the oil in a stable manner, so the initially disconnected trapped oil ganglia coalesce into a bank as the flood progresses. However, the location of surfactants and polymers in the core during a chemical flood is difficult or impossible to determine at very fine time and space resolutions. In this work, we bridge this gap by visualizing saturation profiles in a coreflood-on-a-chip, a micromodel that is the same length as a core, and monitoring fluorescent aqueous injectant as displacements occur. We visualize, for the first time, surfactants in and around oil banks at the pore and Darcy scales during low-tension displacements. We present 12 chemical floods in the coreflood-on-a-chip, imaged at the centimeter scale, including six surfactant and six alkali-surfactant-polymer (ASP) floods at low, intermediate, and high initial water saturations. Additionally, we present a micron-scale visualization of an ASP flood under UV light to observe the distribution of surfactant around an oil bank at the pore scale. We found that oil banks formed even during very unfavorable displacements, when surfactant solution (1 cp) displaced oil (80 cp) in a micromodel at intermediate and residual oil saturations. Although our results show saturation profiles are mostly well described by fractional flow theory, the distribution of injected aqueous phase is not. Significant aqueous injectant, including surfactant, flows within and ahead of oil banks.

Tensor-based reconstruction applied to regularized time-lapse data

SUMMARY Repeatedly recording seismic data over a period of months or years is one way to identify trapped oil and gas and to monitor CO2 injection in underground storage reservoirs and saline aquifers. This process of recording data over time and then differencing the images assumes the recording of the data over a particular subsurface region is repeatable. In other words, the hope is that one can recover changes in the Earth when the survey parameters are held fixed between data collection times. Unfortunately, perfect experimental repeatability almost never occurs. Acquisition inconsistencies such as changes in weather (currents, wind) for marine seismic data are inevitable, resulting in source and receiver location differences between surveys at the very least. Thus, data processing aimed at improving repeatability between baseline and monitor surveys is extremely useful. One such processing tool is regularization (or binning) that aligns multiple surveys with different source or receiver configurations onto a common grid. Data binned onto a regular grid can be stored in a high-dimensional data structure called a tensor with, for example, x and y receiver coordinates and time as indices of the tensor. Such a higher-order data structure describing a subsection of the Earth often exhibits redundancies which one can exploit to fill in gaps caused by sampling the surveys onto the common grid. In fact, since data gaps and noise increase the rank of the tensor, seeking to recover the original data by reducing the rank (low-rank tensor-based completion) successfully fills in gaps caused by binning. The tensor nuclear norm (TNN) is defined by the tensor singular value decomposition (tSVD) which generalizes the matrix SVD. In this work we complete missing time-lapse data caused by binning using the alternating direction method of multipliers (or ADMM) to minimize the TNN. For a synthetic experiment with three parabolic events in which the time-lapse difference involves an amplitude increase in one of these events between baseline and monitor data sets, the binning and reconstruction algorithm (TNN-ADMM) correctly recovers this time-lapse change. We also apply this workflow of binning and TNN-ADMM reconstruction to a real marine survey from offshore Western Australia in which the binning onto a regular grid results in significant data gaps. The data after reconstruction varies continuously without the large gaps caused by the binning process.

Adsorption Study of Novel Gemini Cationic Surfactant in Carbonate Reservoir Cores-Influence of Critical Parameters.

Surfactant flooding is an enhanced oil recovery method that recovers residual and capillary trapped oil by improving pore-scale displacement efficiency. Low retention of injected chemicals is desired to ensure an economic and cost-effective recovery process. This paper examines the adsorption behavior of a novel gemini cationic surfactant on carbonate cores. The rock cores were characterized using an X-ray diffraction (XRD) spectroscope. In addition, the influence of critical parameters on the dynamic adsorption of the cationic gemini surfactant was studied by injecting the surfactant solution through carbonate cores in a core flooding apparatus until an equilibrium state was achieved. The concentration of surfactant was observed using high performance liquid chromatography. Experimental results showed that an increasing surfactant concentration causes higher retention of the surfactant. Moreover, increasing the flow rate to 0.2 mL/min results in lowering the surfactant retention percentage to 17%. At typical high salinity and high temperature conditions, the cationic gemini surfactant demonstrated low retention (0.42 mg/g-rock) on an Indiana limestone core. This study extends the frontier of knowledge in gemini surfactant applications for enhanced oil recovery.